Recovery of liquid hydrocarbons from distillate wells



G. s. BAYs 2,212,143

RECOVERY OF LIQUID HYDROCARBONS FROM DISTILLATE WELLS Aug. zo, 1940.

2 Sheets-Sheet l Filed Sept. 29, 1938 vxm,

Snnentor Ge'oge/ S- ,Z3 c55/5 at Mmmm Aug. 20, 1940.

G. s. BAYs 2,212,143

RECOVERY 0F LIQUID HYDROCARBONS FROM DISTILLATE WELLS Filed sept. 29, 1938 2 Sheets-Sheet 2 Patented Aug.l 20, 1940 RECOVERY F LIQUID PATENT OFFICE HYDROCARBONS FROM DISTILLTE WELLS George S.

Bays, Tulsa,

Okla., lassignor to Stanolind Oil and Gas Company, Tulsa, Okla., a. corporation of Delaware Application September 29, 1938, Serial No. 232,401

`6 Claims.

This invention relates to the recovery oi.' liquid hydrocarbons from distillate wells.

In recent years it has become increasingly frey quent to encounter deep producing formations under high pressures, such as 2000 to 500,0 pounds per square inch, for instance 3000 pounds per square inch, which are characterized by the fact that the fluids entering the base of the well are wholly or largely in the vapor phase. The iluids 10 from these distillate wells contain substantial quantities of normally liquid hydrocarbons.

It is an object of this invention to provide new and improved methods and apparatus for the recovery of these normally liquid hydrocarbons.

Another object of my invention is to increase the amount of these normally liquid hydrocarbons which can be recovered economically. A further object of my invention is to provide methods and apparatusv which will permit low tem- 420 perature operation with an accompanying improvement in recovery.

i Other and more detailed objects, advantages and uses of my invention will become apparent asthe description thereof proceeds.

In dealing with a mixture of hydrocarbons in the'vapor phase it is true in general that as the pressure is increased from atmospheric upwards at a given temperature, a point is reached at which the heavier hydrocarbons begin to condense Vout in the liquid phase.y Furthermore, as the pressure increase is continued the amount of condensation likewise increases. However, a peculiar phenomenon has been observed 'at high pressures and within certain temperature ranges. As the pressure is increased a point is ultimately reached at which no further condensation occurs and beyond which liquid actually tends to vaporize, thus reducing the amount of liquid phase present. This is due to the phenomenon called 40 retrograde vaporization.

Looking at this same phenomenon from the opposite point of view, we may take a mixture of hydrocarbons, for instance the total production of a distillate well in the vapor phase at a high pressure, forinstance 3000 pounds per square inch, and gradually lower the pressure isothermally until a liquid phase commences to form. This formation of a liquid phase may be referred to as retrograde condensation since it is con- 5'0.' densation under decreasing pressure conditionswhile normally liquids condense from the vapor i phase when the pressure is increased rather than decreased. Further decreasing the pressure on the system referred to increases the amount of liquid phase formation until a pointis reached. at

(Cl. (i2-175.5)

which the liquid phase formation reaches a maximum and this point is referred to herein as the optimum retrograde condensation pressure. Further decrease of the pressure decreases the amount of liquid phase present until ultimately a. point is reached under low pressure conditions where the total hydrocarbons are in the ordinary vapor phase condition. 'The value of the optimum retrograde condensation pressure depends, of course, on the composition of the hydrocarbon mixture used and is also somewhat dependent.

on the temperature at which the system is maintained although for considerable ranges of temperatures the optimum retrograde condensation pressure remains approximately constant.

1 As an example of the retrograde condensation phenomenon, if the pressure be increased upon a gas and oil system, condensation of, say, hexane will occur up to a given point, possibly in the neighborhood of 600 pounds per square inch at the particular temperature in effect, for instance F. When the pressure is increased beyond this point, retrograde vaporization takes place and the hexane in the oil body commences to reenter the vapor phase.

My invention utilizes this phenomenon in the production of liquid hydrocarbons from distillate wells. After recovery of the liquid hydrocarbons the remaining gases are preferably recompressed and recycled to the formation from whichthey were produced and the method is thus applicable to the secondary recovery of oil from partially depleted oil reservoirs since the recycled hydrocarbons under high pressure tend to pick up additional liquid phase hydrocarbons by virtue of the retrograde vaporization phenomenon and thus can be recovered continuously.

For instance, in practicing my invention a hydrocarbon gas, preferably natural gas, is injected into the partially depleted reservoir under high pressure through one or more wells which need not be closely spaced-for instance, spacing as high as one injection well per acres can be used. y The pressure ultimately reached must exceed the optimum retrograde condensation press ure by a substantial margin, preferably at least 1000 pounds per square inch. The pressure used can be as high as desired, the main limiting factor being the cost of producing and maintaining excessive pressures. In general I prefer to raise the pressure in the reservoir to a value between about 2500 pounds per square inch and about 5000 pounds per square inch. "if

The gas is allowed to remain in contact with the oil in the partially depleted reservoir at this pressure for a period of at least several days and preferably several months to permit approximate equilibrium to take place within the very fine pores and capillaries of the reservoir.

When this period has been allowed in order to achieve approximate equilibrium, gas is produced from the formation. 'I'his gas may be 'produced from the same wells through which it is introduced and this constitutes an additional advantage over, and distinction from, gas drive and water drive methods which necessarily use separate wells for the driving fluid and the oil produced, but as will hereinafter appear I can, and it is often desirable to, operate on a continuous basis using separate injection and production wells.

The gas is produced at as near reservoir pressure as practicable. In any event the pressure in the formation surrounding the well or wells from which the gas is produced is preferablynot allowedto drop below about 2500 pounds per square inch. It is also desirable that the pressure within the well itself be maintained above these pressures but this is not always essential since condensation within the well results in entrainment and the liquid thus separating out is not lost as it would be if the condensation occurred within the underground formation.

Due to the retrograde vaporization phenomenon, the gas produced under high pressure contains normally liquid hydrocarbons from the underground formation which were dissolved in the gas by virtue of the high pressure. These hydrocarbons can be separted from the gas by merely lowering the pressure to some value equal to or above the optimum retrograde condensation pressure, for instance a pressure of from about 400 pounds per square inch to about 1200 pounds per square inch, and preferably from about 600 pounds per square inch to about 1000 pounds per square inch, and then separating the vapor and liquid phases. If the pressure is lowered below the optimum retrograde condensation pressure,

the liquid phase commences to enter the vapor phase which is usually undesirable. However, although operation slightly below the optimum retrograde condensation pressure yields less total liquid hydrocarbons, there is an increased concentration of butanes and heavier hydrocarbons inthe liquid phase and this makes it possible to recover additional amounts of these desirable hydrocarbons by operating at pressures lower than the optimum retrograde condensation pressurebut above 400, or preferably 600, pounds per square inch as above indicated.

It is highly desirable in accordance with my invention to cool the fluids passing from the well by indirect heat exchange as well as by the Joule- Thomson effect which accompanies the pressure reduction since in this way much greater yields of butanes and heavier hydrocarbons can be obtained asv will hereinafter appear.

While it is possible, as above mentioned, to use the same well for the introduction and withdrawal of gas in accordance with my invention this necessitates discontinuous operation and it is greatly preferable to use different wells.

My invention will be described with particular reference to the accompanying drawings in which Figures l and 2 represent, in diagrammatic form, alternative embodiments of my invention.

A simplified and highly diagrammatic illustration of one type of equipment for practicing my invention is shown in Figure 1. In operating in accordance with Figure 1, gas is introduced at high pressure into well A, passes through the partially depleted oil reservoir I0, which is isolated by impervious Vstrata Il and l2, and byn brine barrier i3, passes into well B at high pressure, is withdrawn from well B through line Il, and has its pressure and temperature reduced to form a liquid phase by virtue of the retrograde condensation effect. This liquid phase is removed by means of separator I5, the gas is recompressed and then reintroduced into well A.

'I'he gas introduced into well A can be composed in whole or in part of recycle gas withdrawn through well B as we have just seen, or `all`-or part of it can come from a separate source, for instance valved line 28. In any event, an extraneous gas is usually necessary for make up purposes, ysince there is inevitably some slight loss. The gas introduced is vconstituted wholly or at least predominantly of one or more hydrocarbons having one or two carbon atoms per molecule. Usually methane is the main constituent, but ethane can be used. Natural gas, or other mixtures of methane and ethane, with or without minor quantities of heavier hydrocarbons, are the most suitableend available materials for use in practicing my invention.

This gas can be introduced at any pressure above about 2500'pounds per square inch but substantially higher pressures are desirable vto provide pressure drops since these figures repre- B0 sent the minimum pressures which should be built up within the reservoir. In any event, of course, the injection pressure must be Well above the formation pressure.

As previously indicated the gas picks up heavier hydrocarbons (largely propane to heptane) from the otherwise unproducible oil lms existing within the `partially depleted oil reservoir I0, and then issues Athrough well B and line H. The pressure is reduced by means of pressure reduction valve I6 to a valve inthe neighborhood of the optimum retrograde condensation pressure or in other words, to a pressure of from about 400 pounds per square inch to about 1200 pounds per square inch, and preferably from about 600 pounds per square inch to about 1000 pounds per square inch.

r'I'his pre'ssure reduction is, of course. accompanied by a temperature reduction and this temperature drop causes further amounts of liquid phase `to separate. However, in order to secure really eiiicient operation with production of an optimum quantity of the total normally liquid hydrocarbons present in the well fluids, it is highly important that additional cooling be used since the cooling available by virtue of the Joule- Thomson effect is very limited.

As an example of the importance of separating liquid hydrocarbons at low temperatures a typical distillate well fluid (Katy Field, Texas) contains 1.181 gallons of hydrocarbons having more than four carbon atoms per 1000 cubic feet (at 60 F., 14.7 pounds per square inch absolute) of hydrocarbon gas composed of hydrocarbons having three or less carbon atoms. This fluid will precipitate 68.0 per cent of these heavier hydrocarbons when trapped at 1000 pounds per square inch and 80 F., but when trapped at the same' pressure and 0 F., 78.7 per cent of the heavier hydrocarbons will be precipitated.

However, when operating with the apparatus shown in Figure 1, a limiting factor with reference to the temperature which can be used is the formation of the so-called natural gas hydrates which occurs at a temperature varying with the pressure used and the composition of the hydrocarbons produced. Thus, it is preferred in accordance with Figure 1 that the temperature at which the liquid phase is separated and removed be from about 25 F. to about 150 F. but preferably from about F. to about '15 F., or,

otherwise stated, above, but preferably within about 10 F. of, the melting point of the natural gas hydrates formed with the particular well i'iuids under consideration at the separation pressure used in accordance with my invention.

Temperature adjustment is obtained by means of cooler I1 which should precede pressure reduction valve II, since in this way the cooling medium used can .be of higher temperature and refrigeration is much less expensive than if the external cooling were applied after the expansion of the well iluid, which is accompanied by cooling occasioned by the Joule-Thomson effect.

Following pressure and temperature adjustf ment,'the fluids` enter 'separator I5, which can be of any conventional type. From this separator the liquid phase, separated by virtue of the retrograde condensation phenomenon is removed through valve I6, which is responsive to liquid level control I0, and then passes through line 20 to storage, or to a fractionation system, or a trap system of stage separation for removal of methane and ethane which can be recycled.

,. Gas, stripped of a majonportion of its com ably is, recycled directly to well A through valve 24 and compressors 25. It will be seen that by opening valve 26 and closing by-pass valves 21,

the compressors can be used in series, while by closing valve 26 and opening the by-pass valves, they can be used in parallel.

In Figure 2 I have provided a system which has numerous advantages over that of Figure 1-but which utilizes the same general principles and is applicable, like the system of 'Figure 1, to either primary or secondary recovery, but while Figure 1 was described with particular reference to secondary recovery Figure.2 will be described with particular reference to primary recovery.

Producing well B is a well of the distillate type and the well head pressure may suitably be from about 2000 to about 5000 pounds per square inch, typically 3000 pounds per square inch. The well head temperature (at well head pressure) will be above F. and usually above 125 F., for instance F. The fluids produced by the well will normally contain some liquid phase material due to the fact that some small amount of the total products may enter the bottom of the well in the liquid phase but due more particularly to the fact that in its upward progress in the well the iiuid encounters a pressure reduction and a temperature reduction which both tend to precipitate liquid phase material.

The well fluids pass through valve |00 which is normally wide open and, therefore, does not serve to give any substantial pressure reduction and, thence, preferably through cooler |0I which may, for instance, lower the temperature of the well fluids to, for instance, 100 F. or some other temperature above that at which hydrates form under these conditions. The cooled fluids, if cooler |0| is operated, pass into separator |02 in which the liquid phase entering the base of the well, that formed in the upward passage through the well and that formed in cooler |0| are separated out and are withdrawn through valve |02 controlled by liquid level controller |04 and pass through line |05 to separator |06. The gases from separator |02 pass out through line 01 and a small lamount of antifreeze solution which can, for instance, be a,calcium chloride solution or other brine, glycerine, glycol or the like, is injected into the line under the control of valve |00. The gases carrying the anti-freeze material, the purpose of which is to avoid clogging of the apparatus by natural gas hydrates, pass through three successive coolers |09, IIO and III although it is to be understood that other cooling arrangements can be used. As shown, cooler |09 operates by indirect heat exchange with the low temperature liquids from separator |06, cooler I|0 operates by indirect heat exchange with the low temperature gases from separator |06 and cooler |I| operates by indirect heat exchange with an external cooling medium which can be cold water or brine, or ammonia or other refrigerant supplied by 'a conventional refrigeration cycle.

With the arrangement as hereinbefore described, and when operating with a produced well uid which is high in moisture content, it is possible that there will be enough moisture contained in the liquids precipitated in separator |02 to cause formation of gas hydrates in line |05 after the considerable pressure drop which occurs at valve |03. To provide for this contingency, an additional antifreeze line I I2 is shown, passing through injection control valve ||3 and into line III as it leaves producing well B, and before it enters cooler |0I.

While the above and subsequent descriptions of these processes refer to use of a recycled and reconcentrated liquid antifreeze solution, it is not imperative that the prevention of hydrate formation be handled in this manner. For instance, it is possible to use a gaseous antifreeze material, which may be recovered and recycled, and it is also possible, although much less advantageous to use a drying apparatus using the principle of adsorption, to eliminate the hydrate-forming.; tendencies of the gas.

The cooled fluids which can suitably be at a temperature of from about 25 F. to about +75 F., or preferably from about 0 F. to about +60 F., pass through line I|5 and valve IIS and are expanded into separator |06. The pressure in separator |06 is controlled by valve ||1 leading to line II 8 for ultimate reinjection through well A. The main pressure drop between separators |02 and |06 is across valves |03 and ||6.

The pressure in separator |06 can, for instance, be the optimum retrograde condensation pressure or slightly lower but, when operating on -a recycling basis, I iind it preferable to use pressures somewhat in excess of the optimum retrograde condensation pressure since these higher pressures result in lower recompression costs. When recycling gas to input well A the pressure in separator |06 can, for instance, -be from about 800 pounds per square inch to about 1500 pounds per square inch, for instance 1000 pounds per separator temperatures can be used as previously described ln connection with Figure 1.

The pressure and temperature reduction result, of course, in the formation of additional quantities o! distillate and, together with the antifreeze material, settle to the bottom of separator |06 and therestratlfy since the aqueous antifreeze material is substantially hydrocarbon insoluble. I'he lower layer of antifreeze ||9 is withdrawn through water leg |20 into trap |2|. The upper layer |22 of hydrocarbon distillate in separator |06 has its upper surface maintained at a constant level by means of float control |23 operating on valve |24'. As the antifreeze accumulates the interface between antifreeze ||9 and distillate |22 rises until a point is reached at which the hydrostatic head of liquid in separator |06 is sufficient to carry the antifreeze over the hump of water leg |20. The pressures in separator |06 and in trap |2| are maintained equal by means of connecting vapor pipe |24. From trap |2| the antifreeze passes through valve |25 controlled by liquid level controller |26 into antifreeze reconcentrator |21 which can be of conventional design and which is not shown in detail. The reconcentrated antifreeze passes through pump |28, line |29 and valve |08 back into the hydrocarbon uids entering coolers |09 to The distillate passes through valve |24, line |30 and heat exchanger |09, where it serves to lower the temperature of the fluids passing to separatorl f| 06.

By passing distillate from. separator |02 through line |05 to separator |06, I flnd that the total yield of distillate can be materially increased. Thus, for example, with South Jennings, Louisiana, well fluid, separator 02 can be operated at well'head pressure and temperature, 3140 pounds per square inch and 130 F. (without using cooler |0|), and separator |06 can be operated at 1200 pounds per square inch and 0 F. With these conditions the total yield of butanes and heavier as liquid formed will be 1.076 gallons per 1000 cubic feet of total propanes and lighter, if distillate is separately withdrawn from separators |02 and |06, while with the arrangement shown in Figure 2, with'the distillate from separator |02 passing to separator |06 as reflux liquid material, to alter the phase conditions existing therein in such a manner as to increase the overall efllciency of this part of the process, the total yield becomes 1.109 gallons per 1000 cubic feet of total propanes and lighter.

After passing through heat exchanger |09, the temperature of the distillate is additionally increased by means of heater |3|. Thus, for instance, this heater can increase the temperature to a value Within the range from about 200 F. to

about 400 F., for instance 350 F., at about the pressure existing in separator |06 although there is, of course, some slight pressure drop. 'I'he purpose of this heating is to drive oil a considerable quantity of the methane and ethane contained in the distillate before the pressure of the distillate is reduced as will hereinafter appear. By using heat to drive off methane and ethane under relatively high pressure conditions, for instance 600 to 1200 pounds per square inch, recompression and stabilization costs are greatly reduced.

From heater |3| the distillate, now containing a considerable amount of vapor phase material, passes into separator |32 were the distillate and vapors separate. The vapor passes overhead through back pressure control valve |33 while the distillate collects in the bottom of the separator and is withdrawn through valve |34 controlled by liquid level controller |35. This distillate can be passed through valve |36 (valves |31 and |38 being closed) directly into stabilizer tower |39, or additional methane and ethane can be removed by hashing the distillate at a lower pressure prior to introduction into stabilizer tower |39 and this is usually' preferable. It can be accomplished by closing valve |36 and opening valves |31 and 38, whereupon the distillate passes into separator |40, the pressure in which is controlled by back pressure control valve 4| at some value substantially less than that existing in separator |32, for instance 300 to 500 pounds per square inch. At this pressure the remaining distillate collects at the bottom of the separator |40 and the low pressure gas passes out through control valve |4| and line |42, whence it passes yeither through valve |43 for recompression and reinjection into input well A or through valve |44 for other use.

Valve |38 is controlled by liquid level controller |45 and the distillate removed through this valve or that coming directly from separator |32 passes through heat exchanger |46 where its temperature is raised by indirect heat exchange with the hot stabilized distillate from stabilizer |39. Supplemental heat is then added by means of heater |41 and the distillate passes into stabilizer tower |39 which can be of conventional design and which is preferably operated at from about 200 to about 400 pounds per square inch, for instance about 350 pounds per square inch. Heat is applied to the bottom of the stabilizer by means of heating coil |48 and reflux is provided by means of dephlegmating coil |49. 'Ihe stabilized ydistillate passes through valve |50, heat exchanger |46 and cooler |5| to product storage tank |52.

While I speak of tower |39 as a stabilizer and while it can advantageously be used to produce a finished natural gasoline of marketable vapor pressure, it is preferable to operate it as a depropanizer, sending all the butane and isobutane to product storage tank |52 which should be of the pressure type.

Relatively high pressure gases from separator 06 pass through line H8, are recompressed by compressor |53 to a pressure substantially higher than that of the uids leaving producingv well B and then pass through valve |54 into input well A. Similarly the gases at slightly lower pressure from separator |32 pass through line |55, are recompressed by compressor |56 and injected into input wall A, and, as previously mentioned, the gases from separator |40 can be recompressed if desired by compressor |51 and similarly reinpressors can be used for all of these gases but since they exist at varying pressures itis preferable to use the arrangement shown.

While I have described my invention in connection with certain specic embodiments thereof, it is tobe understood that these are by. way of illustration and not by way of limitation, and I do not mean to be bound'thereby but only to the subject matter of the appended claims.

I claim: I,

1. A method of producing liquid hydrocarbons from iiuids produced by a lwell lof the distillate type, said uids coming from said well at high pressure, which comprises separating liquid hydrocarbons from the remaining gases at high pressure in a first separation zone, cooling said gases while under high pressure, expanding said gases into a second separation zone maintained at a pressure between about 400 pounds per square inch and about 1200 pounds per square inch, expanding the liquid hydrocarbons from said first separation zone into said second separation optimum retrogradecondensation pressure, expandng liquid hydrocarbons from said first separation zone into said second separation zone as reii/ux liquid to precipitate additional liquid hydrocarbons in said second separation zone, maintaining a liquid-gas interface in said second sep- .Iaration fzone below the point of introduction of said reflux liquid into said second separation zone, and separately withdrawing liquid and gaseous hydrocarbons from said second separation zone.

4. A method of producing liquid hydrocarbons from uids produced by a well of the distillate zone to precipitate additional liquid hydrocarbons l in said second separation zone and separating gaseous from liquid hydrocarbons in said second separation zone. i

2. A method of producing liquid hydrocarbons from fluids produced by a well of the distillate type, said fluids coming from said well at high pressure, which comprises separating liquid hydrocarbons from the remaining gases at highy pressure in a first separation zone, cooling said gases while under pressure, expanding gases from said iirst separation zone into a second separation zone maintained at a pressure between about 800 pounds'per square inch and about 1500 pounds per square inch, expanding liquid hydrocarbons from said rst separation zone into said second separation zone to precipitate additional liquid hydrocarbons in said second separation zone and separating gaseous from liquid hydrocarbons in said second separation zone.

, 3?. A method of producing liquid hydrocarbons from uids produced by a Well of the distillate type, said iiuids coming from said well at high pressure,which' comprises separating liquid hydrocarbons from the remaining gases at high pressure in a first separation zone, cooling said gases while under high pressure, expanding gases from said first separation zone into a second separation zone maintained at a pressure above the -from which said fluid was type, said iiuids coming from said well at high pressure, which comprises cooling said fluids to a temperature above that at which hydrates form from, said uids at said pressure, passing the cooled fluids to 'a iirst separation zone, separating liquid and gaseous hydrocarbons in said iirst separation zone, cooling said gases kwhile under high pressure, expanding said gases into a second separation zone maintained at a pressure between about 400 pounds per square inch and about 1200 pounds per square inch, expanding the liquid hydrocarbons from said rst separation zone into said second separation zone to precipitate additional liquid hydrocarbons in said second separation zone and separating gaseous from liquid hydrocarbons`V in said second separation zone.

5. A method accordingto claim l in which said gases are expanded inthe presence of an antifreeze material.

6. The method of recovering liquid hydrocarbons from'a fluid produced by a well of the distillate type which comprises separating the liquid fraction from said iiuid at about well head pressure and a temperature above that at which natural gas hydrates are formed at said pressure, admixing said fluid after separation of said liq'- uid fraction with an antifreeze material, passing the resulting mixture to a second separation stage maintained at a temperature within the range from about 50 to about +75 F. and a pressure within the range from about 800 to about 1500 pounds per square inch, supplying said liquid fraction to said second separation stage, independently withdrawing antifreeze material, residual gas and a hydrocarbon condensate from said second separation stage and compressing said residual gas for re-injection into the formation produced.

GEORGE S. BAYS. 

